1. Field of the Invention
This invention relates to production systems and methods deployed in subterranean oil and gas wells.
2. Description of the Related Art
Many oil and gas wells will experience liquid loading at some point in their productive lives due to the reservoir's inability to provide sufficient energy to carry wellbore liquids to the surface. The liquids that accumulate in the wellbore may cause the well to cease flowing or flow at a reduced rate. To increase or re-establish the production, operators place the well on artificial lift, which is defined as a method of removing wellbore liquids to the surface by applying a form of energy into the wellbore. Currently, the most common artificial lift systems in the oil and gas' industry are down-hole pumping systems, plunger lift systems, and compressed gas systems.
The most popular form of down-hole pump is the sucker rod pump. It comprises a dual ball and seat assembly, and a pump barrel containing a plunger. A string of sucker rods connects the downhole pump to a pump jack at the surface. The pump jack at the surface provides the reciprocating motion to the rods which in turn provides the reciprocal motion to stroke the pump, which is a fluid displacement device. As the pump strokes, fluids above the pump are gravity fed into the pump chamber and are then pumped up the production tubing and out of the wellbore to the surface facilities. Other downhole pump systems include progressive cavity, jet, electric submersible pumps and others.
A plunger lift system utilizes compressed gas to lift a free piston traveling from the bottom of the tubing in the wellbore to the surface. Most plunger lift systems utilize the energy from a reservoir by closing in the well periodically in order to build up pressure in the wellbore. The well is then opened rapidly which creates a pressure differential, and as the plunger travels to the surface, it lifts reservoir liquids that have accumulated above the plunger. Like the pump, the plunger is also a fluid displacement device.
Compressed gas systems can be either continuous or intermittent. As their names imply, continuous systems continuously inject gas into the wellbore and intermittent systems inject gas intermittently. In both systems, compressed gas flows into the casing-tubing annulus of the well and travels down the wellbore to a gas lift valve contained in the tubing string. If the gas pressure in the casing-tubing annulus is sufficiently high compared to the pressure inside the tubing adjacent to the valve, the gas lift valve will be in the open position which subsequently allows gas in the casing-tubing annulus to enter the tubing and thus lift liquids in the tubing out of the wellbore. Continuous gas lift systems work effectively unless the reservoir has a depletion or partial depletion drive, which results in a pressure decline in the reservoir as fluids are removed. When the reservoir pressure depletes to a point that the gas lift pressure causes significant back pressure on the reservoir, continuous gas lift systems become inefficient and the flow rate from the well is reduced until it is uneconomic to operate the system. Intermittent gas lift systems apply this back pressure intermittently and therefore can operate economically for longer periods of time than continuous systems. Intermittent systems are not as common as continuous systems because of the difficulties and expense of operating surface equipment on an intermittent basis.
Horizontal drilling was developed to access irregular fossil energy deposits in order to enhance the recovery of hydrocarbons. Directional drilling was developed to access fossil energy deposits some distance from the surface location of the wellbore. Generally, both of these drilling methods begin with a vertical hole or well. At a certain point in this vertical well, a turn of the drilling tool is initiated which eventually brings the drilling tool into a deviated position with respect to the vertical position.
It is not practical to install most artificial lift systems in the deviated sections of directional or horizontal wells or deep into the perforated section of vertical wells since down-hole equipment installed in these regions may be inefficient or can undergo high maintenance costs due to wear and/or solids and gas entrained in the liquids interfering with the operation of the pump. Therefore, most operators only install down-hole artificial lift equipment in the vertical portion of the wellbore above the reservoir. In many vertical wells with relatively long perforated intervals, many operators choose to not install artificial lift equipment in the well due to the factors above. Downhole pump systems, plunger lift systems, and compressed gas lift systems are not designed to recover any liquids that exist below the downhole equipment. Therefore, in many vertical, directional, and horizontal wells, a column of liquid ranging from hundreds to many thousands of feet may exist below the down-hole artificial lift equipment. Because of the limitations with current artificial lift systems, considerable hydrocarbon reserves cannot be recovered using conventional methods in depletion or partial depletion drive directional or horizontally drilled wells, and vertical wells with relatively long perforated intervals. Thus, a major problem with the current technology is that reservoir liquids located below conventional down-hole artificial lift equipment cannot be lifted.
There is a need to provide an artificial lift system that will enable the recovery of liquids in the deviated sections of directional or horizontal wellbores, and in vertical wells with relatively long perforated intervals.
There is a need to provide an artificial lift system that will enable the recovery of liquids in vertical wells with relatively long perforated intervals and in the deviated sections of directional and horizontal wellbores with smaller casing diameters.
There is a need to lower the artificial lift point in vertical wells with relatively long perforated intervals and in wells with deviated or horizontal sections.
There is a need to provide a high velocity volume of injection gas to more efficiently sweep the reservoir liquids from the wellbore.
There is a need to provide a more efficient, less costly wellbore liquid removal process.
There is a need for a less costly artificial lift method for vertical wells with relatively long perforated intervals and for wells with deviated or horizontal sections.
There is a need for a less costly and more efficient artificial lift method for wells that still have sufficient reservoir energy and reservoir gas to lift liquids from below to above the downhole artificial lift equipment.
Finally, there is a need to provide a more efficient gas and solid separation method to lower the lift point in wells with deviated and horizontal sections and for vertical wells with relatively long perforated intervals.